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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2022

OR

☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-36505

 

Viper Energy Partners LP

(Exact Name of Registrant As Specified in Its Charter)

DE

46-5001985

(State or Other Jurisdiction of Incorporation or Organization)

(I.R.S. Employer Identification Number)

500 West Texas Ave.

Suite 100

Midland, TX

79701

(Address of principal executive offices)

(Zip code)

(432) 221-7400

(Registrant's telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units

VNOM

The Nasdaq Stock Market LLC

(NASDAQ Global Select Market)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One):

Large Accelerated Filer

☒

Accelerated Filer

☐

Non-Accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.    ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐     No  ☒ 

As of November 4, 2022, the registrant had outstanding 74,185,141 common units representing limited partner interests and 90,709,946 Class B units representing limited partner interests.

---

VIPER ENERGY PARTNERS LP

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2022

TABLE OF CONTENTS

			Page
Glossary of Oil and Natural Gas Terms			ii
Glossary of Certain Other Terms			iii
Cautionary Statement Regarding Forward-Looking Statements			iv
PART I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)			1
Condensed Consolidated Balance Sheets			1
Condensed Consolidated Statements of Operations			2
Condensed Consolidated Statements of Changes to Unitholders’ Equity			3
Condensed Consolidated Statements of Cash Flows			5
Condensed Notes to Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
Item 3. Quantitative and Qualitative Disclosures about Market Risk			28
Item 4. Controls and Procedures			29
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			30
Item 1A. Risk Factors			30
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			30
Item 6. Exhibits			31
Signatures			32

i

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Table of Contents

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and natural gas terms that are used in this Quarterly Report on Form 10-Q (this “report”):

Basin			A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel			One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BO			One barrel of oil.
BO/d			BO per day.
BOE			One barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d			BOE per day.
British Thermal Unit or Btu			The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Condensate			Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Horizontal wells			Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBbls			Thousand barrels of crude oil or other liquid hydrocarbons.
MBOE			One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf			One thousand cubic feet of natural gas.
Mineral interests			The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu			One million British Thermal Units.
MMcf			Million cubic feet of natural gas.
Net royalty acres			Net mineral acres multiplied by the average lease royalty interest and other burdens.
Oil and natural gas properties			Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator			The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Prospect			A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reserves			The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Reserves			The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir			A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interest			An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
Spud			Commencement of actual drilling operations.
WTI			West Texas Intermediate.

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GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this report:

ASU			Accounting Standards Update.
Adjusted EBITDA			Consolidated Adjusted EBITDA, a non-GAAP measure, generally equals its net income (loss) plus net income (loss) attributable to non-controlling interest before interest expense, net, non-cash unit-based compensation expense, depletion expense, non-cash (gain) loss on derivative instruments and provision for (benefit from) income taxes, which measure is used by management to more effectively evaluate the operating performance and determine distributable amounts for purposes of the distribution policy.
Diamondback			Diamondback Energy, Inc., a Delaware corporation.
Exchange Act			The Securities Exchange Act of 1934, as amended.
GAAP			Accounting principles generally accepted in the United States.
General Partner			Viper Energy Partners GP LLC, a Delaware limited liability company, and the General Partner of the Partnership.
LIBOR			The London interbank offered rate.
LTIP			Viper Energy Partners LP Long Term Incentive Plan.
NYMEX			New York Mercantile Exchange.
OPEC			Organization of the Petroleum Exporting Countries.
Operating Company			Viper Energy Partners LLC, a Delaware limited liability company and a consolidated subsidiary of Viper Energy Partners LP.
Partnership			Viper Energy Partners LP, a Delaware limited partnership.
SEC			United States Securities and Exchange Commission.
Notes			The 5.375% Senior Notes due 2027 issued on October 16, 2019.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report are “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions. All statements, other than statements of historical fact, including statements regarding our: future performance; business strategy; future operations; estimates and projections of operating income, losses, costs and expenses, returns, cash flow, and financial position; production levels on properties in which we have mineral and royalty interests, developmental activity by other operators; reserve estimates and our ability to replace or increase reserves; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including Diamondback’s plans for developing our acreage and our cash distribution policy and repurchases of our common units and/or senior notes) are forward-looking statements. When used in this report, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to us are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II. Item 1A. Risk Factors, our Annual Report on Form 10-K for the year ended December 31, 2021, our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022 and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2022 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of the Partnership and the Operating Company.

Factors that could cause the outcomes to differ materially include (but are not limited to) the following:

•Changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities;

•the impact of public health crises, including epidemic or pandemic diseases such as the COVID-19 pandemic, and any related company or government policies or actions;

•actions taken by the members of OPEC and Russia affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;

•changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates, inflation rates and concerns over a potential economic downturn or recession;

•regional supply and demand factors, including delays, curtailment delays or interruptions of production on our mineral and royalty acreage, or governmental orders, rules or regulations that impose production limits on such acreage;

•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;

•physical and transition risks relating to climate change;

•restrictions on the use of water, including limits on the use of produced water by our operators and a moratorium on new produced water well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin;

•significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges;

•changes in U.S. energy, environmental, monetary and trade policies;

•conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development by our operators and environmental and social responsibility projects undertaken by Diamondback and our other operators;

•changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services impacting our operators;

•changes in safety, health, environmental, tax, and other regulations or requirements impacting us or our operators (including those addressing air emissions, water management, or the impact of global climate change);

•security threats, including cybersecurity threats and disruptions to our business from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business;

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•lack of, or disruption in, access to adequate and reliable transportation, processing, storage, and other facilities impacting our operators;

•severe weather conditions;

•acts of war or terrorist acts and the governmental or military response thereto;

•changes in the financial strength of counterparties to the credit agreement and hedging contracts of our operating subsidiary;

•changes in our credit rating; and

•other risks and factors disclosed in this report.

In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, new risks emerge from time to time. We cannot predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this report. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by applicable law.

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PART I. FINANCIAL INFORMATION

ITEM 1.     CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Viper Energy Partners LP

Condensed Consolidated Balance Sheets

(Unaudited)

			September 30,						December 31,
			2022						2021
			(In thousands, except unit amounts)
Assets
Current assets:
Cash and cash equivalents			$	11,616					$	39,448
Royalty income receivable (net of allowance for credit losses)			94,215						68,568
Royalty income receivable—related party			10,267						2,144
Derivative instruments			4,686						—
Other current assets			3,506						989
Total current assets			124,290						111,149
Property:
Oil and natural gas interests, full cost method of accounting ($1,460,744 and $1,640,172 excluded from depletion at September 30, 2022 and December 31, 2021, respectively)			3,493,979						3,513,590
Land			5,688						5,688
Accumulated depletion and impairment			(688,996)						(599,163)
Property, net			2,810,671						2,920,115
Derivative instruments			839						—
Deferred income taxes (net of allowances)			49,656						—
Other assets			301						2,757
Total assets			$	2,985,757					$	3,034,021
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable			$	17					$	69
Accrued liabilities			24,173						20,509
Derivative instruments			891						3,417
Income taxes payable			—						471
Total current liabilities			25,081						24,466
Long-term debt, net			669,638						776,727
Derivative instruments			125						—
Total liabilities			694,844						801,193
Commitments and contingencies (Note 12)
Unitholders’ equity:
General Partner			669						729
Common units (74,156,051 units issued and outstanding as of September 30, 2022 and 78,546,403 units issued and outstanding as of December 31, 2021)			722,397						813,161
Class B units (90,709,946 units issued and outstanding as of September 30, 2022 and December 31, 2021)			857						931
Total Viper Energy Partners LP unitholders’ equity			723,923						814,821
Non-controlling interest			1,566,990						1,418,007
Total equity			2,290,913						2,232,828
Total liabilities and unitholders’ equity			$	2,985,757					$	3,034,021

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Operations

(Unaudited)

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(In thousands, except per unit amounts)
Operating income:
Royalty income			$	219,909					$	127,649					$	651,828					$	337,619
Lease bonus income			1,497						223						10,508						1,032
Other operating income			211						132						506						479
Total operating income			221,617						128,004						662,842						339,130
Costs and expenses:
Production and ad valorem taxes			15,638						8,625						45,547						23,426
Depletion			30,460						25,366						89,833						74,230
General and administrative expenses			2,139						1,735						5,972						6,118
Total costs and expenses			48,237						35,726						141,352						103,774
Income (loss) from operations			173,380						92,278						521,490						235,356
Other income (expense):
Interest expense, net			(10,731)						(8,328)						(30,158)						(24,161)
Gain (loss) on derivative instruments, net			882						(9,599)						(19,366)						(70,649)
Other income, net			162						—						200						77
Total other expense, net			(9,687)						(17,927)						(49,324)						(94,733)
Income (loss) before income taxes			163,693						74,351						472,166						140,623
Provision for (benefit from) income taxes			(46,409)						906						(37,597)						941
Net income (loss)			210,102						73,445						509,763						139,682
Net income (loss) attributable to non-controlling interest			130,762						56,613						379,796						121,208
Net income (loss) attributable to Viper Energy Partners LP			$	79,340					$	16,832					$	129,967					$	18,474
Net income (loss) attributable to common limited partner units:
Basic			$	1.06					$	0.26					$	1.70					$	0.28
Diluted			$	1.06					$	0.26					$	1.70					$	0.28
Weighted average number of common limited partner units outstanding:
Basic			74,943						64,152						76,215						64,724
Diluted			74,943						64,241						76,325						64,815

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Changes to Unitholders' Equity

(Unaudited)

			Limited Partners																								General Partner						Non-Controlling Interest
			Common												Class B												Amount						Amount
			Units						Amount						Units						Amount																					Total
			(In thousands)
Balance at December 31, 2021			78,546						$	813,161					90,710						$	931					$	729					$	1,418,007								$	2,232,828
Unit-based compensation			—						284						—						—						—						—									284
Distribution equivalent rights payments			—						(64)						—						—						—						—									(64)
Distributions to public			—						(35,830)						—						—						—						—									(35,830)
Distributions to Diamondback			—						(344)						—						(25)						—						(42,634)									(43,003)
Distributions to General Partner			—						—						—						—						(20)						—									(20)
Change in ownership of consolidated subsidiaries, net			—						14,195						—						—						—						(14,195)									—
Repurchased units as part of unit buyback			(1,580)						(39,260)						—						—						—						—									(39,260)
Net income (loss)			—						16,605						—						—						—						111,436									128,041
Balance at March 31, 2022			76,966						768,747						90,710						906						709						1,472,614									2,242,976
Unit-based compensation			—						335						—						—						—						—									335
Distribution equivalent rights payments			—						(113)						—						—						—						—									(113)
Distributions to public			—						(51,077)						—						—						—						—									(51,077)
Distributions to Diamondback			—						(490)						—						(25)						—						(63,497)									(64,012)
Distributions to General Partner			—						—						—						—						(20)						—									(20)
Change in ownership of consolidated subsidiaries, net			—						11,523						—						—						—						(11,523)									—
Repurchased units as part of unit buyback			(1,020)						(28,949)						—						—						—						—									(28,949)
Net income (loss)			—						34,022						—						—						—						137,598									171,620
Balance at June 30, 2022			75,946						733,998						90,710						881						689						1,535,192									2,270,760
Unit-based compensation			—						362						—						—						—						—									362
Vesting of restricted stock units			28						—						—						—						—						—									—
Distribution equivalent rights payments			—						(132)						—						—						—						—									(132)
Distributions to public			—						(59,901)						—						—						—						—									(59,901)
Distributions to Diamondback			—						(593)						—						(24)						—						(78,918)									(79,535)
Distributions to General Partner			—						—						—						—						(20)						—									(20)
Change in ownership of consolidated subsidiaries, net			—						20,046						—						—						—						(20,046)									—
Repurchased units as part of unit buyback			(1,818)						(50,723)						—						—						—						—									(50,723)
Net income (loss)			—						79,340						—						—						—						130,762									210,102
Balance at September 30, 2022			74,156						$	722,397					90,710						$	857					$	669					$	1,566,990								$	2,290,913

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Changes to Unitholders' Equity - (Continued)

(Unaudited)

			Limited Partners																								General Partner						Non-Controlling Interest
			Common												Class B												Amount						Amount
			Units						Amount						Units						Amount																					Total
			(In thousands)
Balance at December 31, 2020			65,817						$	633,415					90,710						$	1,031					$	809					$	1,225,578								$	1,860,833
Unit-based compensation			—						315						—						—						—						—									315
Vesting of restricted stock units			3						—						—						—						—						—									—
Distribution equivalent rights payments			—						(24)						—						—						—						—									(24)
Distributions to public			—						(9,036)						—						—						—						—									(9,036)
Distributions to Diamondback			—						(102)						—						(25)						—						(12,699)									(12,826)
Distributions to General Partner			—						—						—						—						(20)						—									(20)
Change in ownership of consolidated subsidiaries, net			—						2,687						—						—						—						(2,687)									—
Cash paid for tax withholding on vested common units			—						(20)						—						—						—						—									(20)
Repurchased units as part of unit buyback			(870)						(13,043)						—						—						—						—									(13,043)
Net income (loss)			—						(3,020)						—						—						—						26,879									23,859
Balance at March 31, 2021			64,950						611,172						90,710						1,006						789						1,237,071									1,850,038
Unit-based compensation			—						338						—						—						—						—									338
Distribution equivalent rights payments			—						(55)						—						—						—						—									(55)
Distributions to public			—						(15,992)						—						—						—						—									(15,992)
Distributions to Diamondback			—						(183)						—						(25)						—						(22,678)									(22,886)
Distributions to General Partner			—						—						—						—						(20)						—									(20)
Change in ownership of consolidated subsidiaries, net			—						1,614						—						—						—						(1,614)									—
Repurchased units as part of unit buyback			(404)						(6,779)												—						—						—									(6,779)
Net income (loss)			—						4,662						—						—						—						37,716									42,378
Balance at June 30, 2021			64,546						594,777						90,710						981						769						1,250,495									1,847,022
Unit-based compensation			—						243						—						—						—						—									243
Vesting of restricted stock units			50						—						—						—						—						—									—
Distribution equivalent rights payments			—						(62)						—						—						—						—									(62)
Distributions to public			—						(20,933)						—						—						—						—									(20,933)
Distributions to Diamondback			—						(240)						—						(25)						—						(29,936)									(30,201)
Distributions to General Partner			—						—						—						—						(20)						—									(20)
Change in ownership of consolidated subsidiaries, net			—						4,115						—						—						—						(4,115)									—
Repurchased units as part of unit buyback			(765)						(13,740)						—						—						—						—									(13,740)
Net income (loss)			—						16,832						—						—						—						56,613									73,445
Balance at September 30, 2021			63,831						$	580,992					90,710						$	956					$	749					$	1,273,057								$	1,855,754

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Consolidated Statements of Cash Flows

(Unaudited)

			Nine Months Ended September 30,
			2022						2021
			(In thousands)
Cash flows from operating activities:
Net income (loss)			$	509,763					$	139,682
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes			(49,656)						—
Depletion			89,833						74,230
(Gain) loss on derivative instruments, net			19,366						70,649
Net cash receipts (payments) on derivatives			(27,292)						(61,188)
Other			4,372						3,332
Changes in operating assets and liabilities:
Royalty income receivable			(25,647)						(14,923)
Royalty income receivable—related party			(8,123)						(20,024)
Accounts payable and accrued liabilities			3,612						7,902
Other			(2,987)						12
Net cash provided by (used in) operating activities			513,241						199,672
Cash flows from investing activities:
Acquisitions of oil and natural gas interests			(38,334)						(6,728)
Proceeds from sale of oil and natural gas interests			57,945						—
Net cash provided by (used in) investing activities			19,611						(6,728)
Cash flows from financing activities:
Proceeds from borrowings under credit facility			229,000						87,000
Repayment on credit facility			(288,000)						(79,000)
Repayment of senior notes			(48,963)						—
Repurchased units as part of unit buyback			(118,932)						(33,562)
Distributions to public			(147,117)						(46,102)
Distributions to Diamondback			(186,550)						(65,913)
Other			(122)						(2,948)
Net cash provided by (used in) financing activities			(560,684)						(140,525)
Net increase (decrease) in cash and cash equivalents			(27,832)						52,419
Cash, cash equivalents and restricted cash at beginning of period			39,448						19,121
Cash, cash equivalents and restricted cash at end of period			$	11,616					$	71,540

See accompanying notes to condensed consolidated financial statements.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements

(Unaudited)

1.    ORGANIZATION AND BASIS OF PRESENTATION

Organization

Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin.

As of September 30, 2022, Viper Energy Partners GP LLC (the “General Partner”) held a 100% general partner interest in the Partnership and Diamondback Energy, Inc. (“Diamondback”) beneficially owned approximately 55% of the Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner.

Basis of Presentation

The accompanying condensed consolidated financial statements and related notes thereto were prepared in accordance with GAAP. All material intercompany balances and transactions have been eliminated upon consolidation. We report our operations in one reportable segment.

These condensed consolidated financial statements have been prepared by the Partnership without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This report should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2021, which contains a summary of the Partnership’s significant accounting policies and other disclosures.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, unitholders’ equity, results of operations or cash flows.

2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities as of the date of the financial statements.

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, the effects of COVID-19, the war in Ukraine and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets continued to contribute to economic and pricing volatility. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts.

The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests, the recoverability of costs of unevaluated properties, the fair value determination of assets and liabilities, including

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

those acquired by the Partnership, fair value estimates of commodity derivatives and estimates of income taxes, including deferred tax valuation allowances.

Related Party Transactions

During the three and nine months ended September 30, 2022, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $0.4 million and $6.7 million, respectively, of lease bonus income primarily related to certain leases acquired in the Swallowtail Acquisition.

All other significant related party transactions with Diamondback or its affiliates have been stated on the face of the consolidated financial statements included elsewhere in this report as of September 30, 2022 and for the three and nine months ended September 30, 2022 and 2021.

Accrued Liabilities

Accrued liabilities consist of the following:

			September 30,						December 31,
			2022						2021
			(In thousands)
Interest payable			$	9,694					$	4,430
Ad valorem taxes payable			11,075						6,201
Derivatives instruments payable			2,252						8,879
Other			1,152						999
Total accrued liabilities			$	24,173					$	20,509

Recent Accounting Pronouncements

Recently Adopted Pronouncements

There are no recently adopted pronouncements.

Accounting Pronouncements Not Yet Adopted

The Partnership considers the applicability and impact of all ASUs. There are no recent accounting pronouncements not yet adopted that are expected to have a material effect on the Partnership upon adoption, as applicable.

3.    REVENUE FROM CONTRACTS WITH CUSTOMERS

Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.

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Viper Energy Partners LP

Condensed Notes to Consolidated Financial Statements - (Continued)

(Unaudited)

The following table disaggregates the Partnership’s total royalty income by product type:

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(In thousands)
Oil income			$	167,934					$	100,154					$	514,180					$	272,450
Natural gas income			28,638						12,074						67,621						30,651
Natural gas liquids income			23,337						15,421						70,027						34,518
Total royalty income			$	219,909					$	127,649					$	651,828					$	337,619

4.    ACQUISITIONS AND DIVESTITURES

2022 Activity

Acquisitions

In the third quarter of 2022, the Partnership acquired, from unrelated third-party sellers, mineral and royalty interests representing 165 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $40.1 million, subject to post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

Divestitures

In the first quarter of 2022, the Partnership divested 325 net royalty acres of third party operated acreage located entirely in Upton and Reagan counties in the Midland Basin for a net sales price of $29.3 million, including post-closing adjustments.

In the third quarter of 2022, the Partnership divested 93 net royalty acres of third party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate sales price of $29.9 million, subject to closing adjustments.

2021 Activity

Swallowtail Acquisition

On October 1, 2021, the Partnership and the Operating Company acquired certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC (the “Swallowtail entities”) pursuant to a definitive purchase and sale agreement for approximately 15.25 million common units and approximately $225.3 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent 2,313 net royalty acres primarily in the Northern Midland Basin, of which 62% were operated by Diamondback as of December 31, 2021. The Swallowtail Acquisition has an effective date of August 1, 2021. In accordance with the terms of the purchase agreement, the Partnership deposited $30.0 million into an escrow account in August 2021, which was released upon the closing of the transaction in October 2021. The cash portion of this transaction was funded through a combination of cash on hand and approximately $190.0 million of borrowings under the Operating Company’s revolving credit facility.

Other 2021 Acquisitions

Additionally during the year ended December 31, 2021, the Partnership acquired, from unrelated third party sellers, mineral and royalty interests representing 1,277 gross (392 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $55.1 million, after post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.

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5.    OIL AND NATURAL GAS INTERESTS

Oil and natural gas interests include the following:

			September 30,						December 31,
			2022						2021
			(In thousands)
Oil and natural gas interests:
Subject to depletion			$	2,033,235					$	1,873,418
Not subject to depletion			1,460,744						1,640,172
Gross oil and natural gas interests			3,493,979						3,513,590
Accumulated depletion and impairment			(688,996)						(599,163)
Oil and natural gas interests, net			2,804,983						2,914,427
Land			5,688						5,688
Property, net of accumulated depletion and impairment			$	2,810,671					$	2,920,115

As of September 30, 2022 and December 31, 2021, the Partnership had mineral and royalty interests representing 26,789 and 27,027 net royalty acres, respectively.

No impairment expense was recorded on the Partnership’s oil and natural gas interests for the three and nine months ended September 30, 2022 and 2021 based on the results of the respective quarterly ceiling tests. In addition to commodity prices, the Partnership’s production rates, levels of proved reserves, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If the trailing 12-month commodity prices decline as compared to the commodity prices used in prior quarters, the Partnership may have material write-downs in subsequent quarters.

6.    DEBT

Long-term debt consisted of the following as of the dates indicated:

			September 30,						December 31,
			2022						2021
			(In thousands)
5.375% senior unsecured notes due 2027			$	430,350					$	479,938
Revolving credit facility			245,000						304,000
Unamortized debt issuance costs			(1,374)						(1,757)
Unamortized discount			(4,338)						(5,454)
Total long-term debt			$	669,638					$	776,727

Repurchases of Notes

During the nine months ended September 30, 2022, the Partnership repurchased an aggregate $49.6 million principal amount of the outstanding Notes for total cash consideration of $49.0 million, which resulted in an immaterial loss on extinguishment of debt during the nine months ended September 30, 2022 after including accrued interest and the write-off of related unamortized costs. The Partnership funded the debt repurchases through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility.

The Operating Company’s Revolving Credit Facility

The Operating Company’s credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base of $580.0 million based on the Operating Company’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November. As of September 30, 2022, the Operating Company had elected a commitment amount of $500.0 million, with

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$245.0 million of outstanding borrowings and $255.0 million available for future borrowings. During the three and nine months ended September 30, 2022 and 2021, the weighted average interest rates on the Operating Company’s revolving credit facility were 4.75%, 3.53%, 1.98% and 2.14%, respectively. The revolving credit facility will mature on June 2, 2025.

As of September 30, 2022, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement.

7.    UNITHOLDERS’ EQUITY AND DISTRIBUTIONS

The Partnership has General Partner and limited partner units. At September 30, 2022, the Partnership had a total of 74,156,051 common units issued and outstanding and 90,709,946 Class B units issued and outstanding, of which 731,500 common units and 90,709,946 Class B units were beneficially owned by Diamondback, representing approximately 55% of the Partnership’s total units outstanding. At September 30, 2022, Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 55% non-controlling ownership interest in the Operating Company. The Operating Company units and the Partnership’s Class B units beneficially owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

Common Unit Repurchase Program

The board of directors of the Partnership’s General Partner has approved a common unit repurchase program to acquire up to $750.0 million of the Partnership’s outstanding common units over an indefinite period of time. The Partnership intends to purchase common units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of the Partnership’s General Partner at any time. During the three and nine months ended September 30, 2022 and 2021, the Partnership repurchased approximately $50.7 million, $118.9 million, $13.7 million and $33.6 million of common units under the repurchase program, respectively. Repurchases for the nine months ended September 30, 2022 include approximately $37.3 million for the repurchase of 1.5 million common units from a significant unitholder in a privately negotiated transaction in the first quarter of 2022. As of September 30, 2022, $561.0 million remains available for use to repurchase common units under the repurchase program.

Cash Distributions on Common Units

The board of directors of the General Partner has established a distribution policy whereby the Operating Company distributes all or a portion of its available cash on a quarterly basis to its unitholders (including Diamondback and the Partnership). The Partnership in turn distributes all or a portion of the available cash it receives from the Operating Company to its common unitholders. The Partnership’s available cash and the available cash of the Operating Company for each quarter is determined by the board of directors of the General Partner following the end of such quarter. The cash available for distribution by the Operating Company, a non-GAAP measure, generally equals the Partnership’s consolidated Adjusted EBITDA for the applicable quarter, less cash needed for income taxes payable, debt service, contractual obligations, fixed charges and reserves for future operating or capital needs that the board of directors of the General Partner deems necessary or appropriate, lease bonus income, distribution equivalent rights payments and preferred distributions, if any. The Partnership’s cash available for distribution for each quarter generally equals the Partnership’s proportional share of the cash distributed by the Operating Company for the quarter, less cash needed by the Partnership for the payment of income taxes, if any, and the preferred distribution. Further, in July 2022, the board of directors of the General Partner approved a distribution policy, effective beginning with the Partnership’s distribution payable for the third quarter of 2022, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our common unit repurchase program. The board updated the distribution policy in November 2022, providing that lease bonus payments and other similar, one-time, non-recurring payments will be excluded from the calculation of the Partnership’s and the Operating Company’s available cash.

The percentage of cash available for distribution pursuant to the distribution policy discussed above may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet while also expanding the return of capital program through the Partnership’s common unit repurchase program. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other basis.

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The following table presents information regarding cash distributions approved by the board of directors of the General Partner for the periods presented (in thousands, except for per share amounts):

Period						Amount per Operating Company Unit						Operating Company Distributions to Diamondback						Amount per Common Unit						Distributions to Common Unitholders(1)						Declaration Date						Unitholder Record Date						Payment Date
Q4 2021						$	0.47					$	42,634					$	0.47					$	36,238					February 16, 2022						March 4, 2022						March 11, 2022
Q1 2022						$	0.70					$	63,497					$	0.67					$	51,680					April 27, 2022						May 12, 2022						May 19, 2022
Q2 2022						$	0.87					$	78,918					$	0.81					$	60,626					July 26, 2022						August 16, 2022						August 23, 2022

(1)Includes amounts paid to Diamondback for the 731,500 common units beneficially owned by Diamondback and distribution equivalent rights payments.

Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter.

Change in Ownership of Consolidated Subsidiaries

Non-controlling interest in the accompanying condensed consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. Diamondback’s relative ownership interest in the Operating Company can change due to the Partnership’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on the Partnership’s units. These changes in ownership percentage and the disproportionate allocation of net income (loss) to Diamondback discussed below result in adjustments to non-controlling interest and common unitholder equity, tax effected, but do not impact earnings. The following table summarizes the changes in common unitholder equity due to changes in ownership interest during the period:

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(In thousands)
Net income (loss) attributable to the Partnership			$	79,340					$	16,832					$	129,967					$	18,474
Change in ownership of consolidated subsidiaries			20,046						4,115						45,764						8,416
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest			$	99,386					$	20,947					$	175,731					$	26,890

Allocation of Net Income

The Partnership, as managing member of the Operating Company, has entered into an agreement, as amended on December 28, 2021, whereby special allocations of the Operating Company’s income and gains over losses and deductions (but before depletion) are to be made to Diamondback through December 31, 2022. These special income allocations reduce the taxable income allocated to the Partnership’s common unitholders.

8.    EARNINGS PER COMMON UNIT

The net income (loss) per common unit on the condensed consolidated statements of operations is based on the net income (loss) attributable to the Partnership’s common units for the three and nine months ended September 30, 2022 and 2021.

The Partnership’s net income (loss) is allocated wholly to the common units, as the General Partner does not have an economic interest.

Basic and diluted earnings per common unit is calculated using the two-class method. The two class method is an earnings allocation proportional to the respective ownership among holders of common units and participating securities. Basic net income (loss) per common unit is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested common units granted under the LTIP.

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A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below:

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(In thousands, except per unit amounts)
Net income (loss) attributable to the period			$	79,340					$	16,832					$	129,967					$	18,474
Less: net income (loss) allocated to participating securities(1)			(173)						(62)						(309)						(141)
Net income (loss) attributable to common unitholders			$	79,167					$	16,770					$	129,658					$	18,333
Weighted average common units outstanding:
Basic weighted average common units outstanding			74,943						64,152						76,215						64,724
Effect of dilutive securities:
Potential common units issuable(2)			—						89						110						91
Diluted weighted average common units outstanding			74,943						64,241						76,325						64,815
Net income (loss) per common unit, basic			$	1.06					$	0.26					$	1.70					$	0.28
Net income (loss) per common unit, diluted			$	1.06					$	0.26					$	1.70					$	0.28

(1)    Restricted stock units with non-forfeitable distribution equivalent rights granted to employees are considered participating securities.

(2) For the three and nine months ended September 30, 2022, and the three months ended September 30, 2021,there were no potential common units excluded from the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive. For the nine months ended September 30, 2021, 2,955 potential common units were excluded in the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive.

9.    INCOME TAXES

The following table provides the Partnership’s provision for (benefit from) income taxes and the effective income tax rate for the dates indicated:

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(In thousands, except for tax rate)
Provision for (benefit from) income taxes			$	(46,409)					$	906					$	(37,597)					$	941
Effective tax rate			(28.4)		%				1.2		%				(8.0)		%				0.7		%

The Partnership’s effective income tax rates for the three and nine months ended September 30, 2022 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of maintaining a valuation allowance on the Partnership’s deferred tax assets. During the three months ended September 30, 2022, the Partnership recognized discrete income tax benefit of $49.7 million related to a partial release of its beginning-of-the-year valuation allowance, based on a change in judgment about the realizability of its deferred tax assets in future years. Management’s assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets as required by applicable accounting standards, resulted in recognition of tax benefit for the portion of the Partnership’s deferred tax assets considered more likely than not to be realized. The positive evidence assessed included recent cumulative income due in part to higher commodity prices and an expectation of future taxable income based upon recent actual and forecasted production volumes and prices. The Partnership retained a partial valuation allowance on its deferred tax assets due in part to potential future volatility in commodity prices impacting the likelihood of future realizability. As of September 30, 2022, the Partnership had a deferred tax asset of $152.7 million offset by an allowance of $103.0 million.

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The Partnership’s effective income tax rates for the three and nine months ended September 30, 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of maintaining a valuation allowance on the Partnership’s deferred tax assets.

As of September 30, 2021, the Partnership maintained a full valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets.

The CHIPS and Science Act of 2022 (“CHIPS”) was enacted on August 9, 2022, and the Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, which created a 15% corporate alternative minimum tax on profits of corporations whose average financial statement income exceeds $1 billion, and included several other provisions applicable to U.S. income taxes for corporations. The Partnership considered the impact of this legislation in the period of enactment and concluded there was not a material impact to the Partnership’s current or deferred income tax balances.

10.    DERIVATIVES

All derivative financial instruments are recorded at fair value. The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the condensed consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

Commodity Contracts

The Partnership historically has used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At September 30, 2022, the Partnership has costless collars, put options and basis swaps outstanding.

Under the Partnership’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to the Partnership and when the settlement price is above the ceiling price, the Partnership is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

Put options have a defined strike price, or floor price. The Partnership pays its counterparty a premium to enter into these derivative contracts, which are deferred until settlement. When the settlement price is below the floor price, the counterparty pays the Partnership an amount equal to the difference between the settlement price and the strike price multiplied by the derivative contract volume. When the settlement price is above the floor price, the put option expires worthless.

The Partnership’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing) and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk. The Partnership’s counterparties are all participants in the amended and restated credit agreement, which is secured by substantially all of the assets of the Operating Company; therefore, the Partnership is not required to post any collateral. The Partnership’s counterparties have been determined to have an acceptable credit risk; therefore, the Partnership does not require collateral from its counterparties.

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As of September 30, 2022, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

															Swaps									Collars									Puts
Settlement Month			Settlement Year			Type of Contract			Bbls/Mcf Per Day			Index			Weighted Average Differential									Weighted Average Floor Price			Weighted Average Ceiling Price						Strike Price
OIL
Oct. - Dec.			2022			Collars			4,000			WTI Cushing			$—									$50.00			$128.01						$—
Oct. - Dec.			2022			Puts(1)			8,000			WTI Cushing			$—									$—			$—						$55.00
Jan. - Mar.			2023			Puts(2)			8,000			WTI Cushing			$—									$—			$—						$54.25
Jan. - Dec.			2023			Basis Swap(3)			2,000			Argus WTI Midland			$0.95									$—			$—						$—
NATURAL GAS
Oct. - Dec.			2022			Collars			20,000			Henry Hub			$—									$2.50			$4.62						$—
Jan. - Dec.			2023			Basis Swap(3)			30,000			Waha Hub			$(1.33)									$—			$—						$—

(1) Includes a deferred premium at a weighted average price of $1.54/Bbl.

(2) Includes a deferred premium at a weighted average price of $1.90/Bbl.

(3) The Partnership has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing, Oklahoma oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.

Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 11—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments included in the condensed consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented:

			Three Months Ended September 30,												Nine Months Ended September 30,
			2022						2021						2022						2021
			(In thousands)
Gain (loss) on derivative instruments			$	882					$	(9,599)					$	(19,366)					$	(70,649)
Net cash receipts (payments) on derivatives(1)			$	(10,263)					$	(25,306)					$	(27,292)					$	(61,188)

(1)The three and nine months ended September 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $2.4 million and $6.6 million, respectively.

11.    FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Partnership’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and

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their placement within the fair value hierarchy. The Partnership uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Partnership’s derivative instruments. The fair values of the Partnership’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties and (iv) the resulting net amounts presented in the Partnership’s condensed consolidated balance sheets as of September 30, 2022 and December 31, 2021. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

			As of September 30, 2022
			Level 1			Level 2			Level 3			Total Gross Fair Value			Gross Amounts Offset in Balance Sheet			Net Fair Value Presented in Balance Sheet
			(In thousands)
Assets:
Current:
Derivative instruments			$	—		$	9,872		$	—		$	9,872		$	(5,186)		$	4,686
Non-current:
Derivative instruments			$	—		$	1,058		$	—		$	1,058		$	(219)		$	839
Liabilities:
Current:
Derivative instruments			$	—		$	6,077		$	—		$	6,077		$	(5,186)		$	891
Non-current:
Derivative instruments			$	—		$	344		$	—		$	344		$	(219)		$	125

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			As of December 31, 2021
			Level 1			Level 2			Level 3			Total Gross Fair Value			Gross Amounts Offset in Balance Sheet			Net Fair Value Presented in Balance Sheet
			(In thousands)
Assets:
Current:
Derivative instruments			$	—		$	1,921		$	—		$	1,921		$	(1,921)		$	—
Liabilities:
Current:
Derivative instruments			$	—		$	5,338		$	—		$	5,338		$	(1,921)		$	3,417

Assets and Liabilities Not Recorded at Fair Value

The following table provides the fair value of financial instruments that are not recorded at fair value in the condensed consolidated balance sheets:

			September 30, 2022												December 31, 2021
			Carrying Value						Fair Value						Carrying Value						Fair Value
			(In thousands)
Debt:
Revolving credit facility			$	245,000					$	245,000					$	304,000					$	304,000
5.375% senior notes due 2027(1)			$	424,638					$	399,180					$	472,727					$	498,992

(1) The carrying value includes associated deferred loan costs and any discount.

The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was determined using the September 30, 2022 quoted market price, a Level 1 classification in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include mineral and royalty interests acquired in asset acquisitions and subsequent write-downs of our proved oil and natural gas interests to fair value when they are impaired or held for sale.

Fair Value of Financial Assets

The Partnership has other financial instruments consisting of cash and cash equivalents, royalty income receivable, other current assets, accounts payable and accrued liabilities. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.

12.    COMMITMENTS AND CONTINGENCIES

The Partnership is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Partnership, cannot be predicted with certainty, the Partnership’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Partnership’s assessment. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

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13.    SUBSEQUENT EVENTS

Cash Distribution

On November 3, 2022, the board of directors of the General Partner approved a cash distribution for the third quarter of 2022 of $0.49 per common unit, payable on November 25, 2022, to eligible unitholders of record at the close of business on November 17, 2022. The distribution consists of a base quarterly distribution of $0.25 per common unit and a variable quarterly distribution of $0.24 per common unit.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2021. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are a publicly traded Delaware limited partnership formed by Diamondback to own and acquire mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin. We operate in one reportable segment. Since May 10, 2018, we have been treated as a corporation for U.S. federal income tax purposes.

Recent Developments

Commodity Prices

Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the future, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2022 and 2021, NYMEX WTI, has ranged from $47.62 to $123.70 per Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $2.45 to $9.68 per MMBtu, with seven-year highs reached in 2022. The war in Ukraine, the COVID-19 pandemic, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and recent measures to combat persistent inflation have continued to contribute to economic and pricing volatility during 2022. Additionally, OPEC and its non-OPEC allies, known collectively as OPEC+, continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels, and has planned production decreases in order to stabilize oil prices during the fourth quarter. However, pricing may remain volatile during the remainder of 2022. We cannot reasonably predict whether production levels will remain at current levels or the impact the full extent of the events above may have on our industry and our business.

Although average oil prices decreased during the third quarter of 2022 from the second quarter of 2022, the commodity prices and industry conditions remained favorable and, based on the results of the quarterly ceiling test, we were not required to record an impairment on our proved oil and natural gas interests for the quarter ended September 30, 2022. If commodity prices deteriorate, we may be required to record impairments in future periods and such impairments could be material. Further, if commodity prices decrease, our production, proved reserves and cash flows may be adversely impacted. Our business may also be adversely impacted by any pipeline capacity and storage constraints.

Acquisitions and Divestitures Update

In the third quarter of 2022, we acquired, from unrelated third-party sellers, mineral and royalty interests representing 165 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $40.1 million, subject to post-closing adjustments. We divested 93 net royalty acres of third party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate sales price of $29.9 million, subject to closing adjustments. Our footprint of mineral and royalty interests totaled 26,789 net royalty acres at September 30, 2022.

Cash Distributions on Common Units

In July 2022, the board of directors of our General Partner approved a distribution policy, effective beginning with our distribution payable for the third quarter of 2022, consisting of a base and variable distribution, that takes into account capital returned to unitholders via our unit buyback program. The board updated the distribution policy in November 2022, providing that lease bonus payments and other similar, one-time, non-recurring payments will be excluded from the calculation of the Partnership’s and the Operating Company’s available cash.

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Production and Operational Update

Third party operated net wells turned to production on our acreage during the third quarter of 2022 are at their highest level since the second quarter of 2019, and third party operated gross wells turned to production during the quarter were the highest in the Partnership’s history. There are currently 49 rigs operating on our mineral and royalty acreage, 11 of which are operated by Diamondback. Although demand for oil and natural gas and commodity prices have increased in the current year, Diamondback and certain of our other operators have kept production on our acreage relatively flat during 2022 and expect to maintain relatively flat volumes in the fourth quarter of 2022 and the first quarter of 2023. Our production and free cash flow outlooks are expected to be driven by Diamondback’s continued focus on developing our acreage, as well as our exposure to other well-capitalized operators in the Permian Basin. As a result of Diamondback’s consistent focus on developing our high concentration royalty acreage, primarily in the Northern Midland Basin, we expect our Diamondback-operated full year 2023 oil production to increase by approximately 10% compared to 2022.

The following table summarizes our gross well information as of the dates indicated:

			Diamondback Operated						Third Party Operated						Total
Horizontal wells turned to production (third quarter 2022)(1):
Gross wells			52						221						273
Net 100% royalty interest wells			2.8						2.0						4.8
Average percent net royalty interest			5.4		%				0.9		%				1.7		%
Horizontal producing well count (as of October 20, 2022):
Gross wells			1,504						4,838						6,342
Net 100% royalty interest wells			113.6						63.7						177.3
Average percent net royalty interest			7.6		%				1.3		%				2.8		%
Horizontal active development well count (as of October 20, 2022)(2):
Gross wells			95						475						570
Net 100% royalty interest wells			5.5						5.1						10.6
Average percent net royalty interest			5.7		%				1.1		%				1.8		%
Line of sight wells (as of October 20, 2022)(3):
Gross wells			166						354						520
Net 100% royalty interest wells			8.3						3.6						11.9
Average percent net royalty interest			5.0		%				1.0		%				2.3		%

(1) Average lateral length of 10,880.

(2) The total 570 gross wells currently in the process of active development are those wells that have been spud and are expected to be turned to production within approximately the next six to eight months.

(3) The total 520 gross line-of-sight wells are those that are not currently in the process of active development, but for which we have reason to believe that they will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third party operators or Diamondback’s current expected completion schedule. Existing permits or active development of our royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices.

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Comparison of the Three Months Ended September 30, 2022 and June 30, 2022

As noted in “—Recent Developments,” the markets for oil and natural gas are highly volatile and are influenced by a number of factors which can lead to significant changes in our results of operations and management’s operational strategy on a quarterly basis. Accordingly, our results of operations discussion focuses on a comparison of the current quarter’s results of operations with those of the immediately preceding quarter. We believe our discussion provides investors with a more meaningful analysis of material operational and financial changes which occurred during the quarter based on current market and operational trends.

Results of Operations

The following table summarizes our income and expenses for the periods indicated:

			Three Months Ended
			September 30, 2022						June 30, 2022
			(In thousands)
Operating income:
Oil income			$	167,934					$	191,195
Natural gas income			28,638						23,793
Natural gas liquids income			23,337						23,842
Royalty income			219,909						238,830
Lease bonus income			1,497						329
Other operating income			211						163
Total operating income			221,617						239,322
Costs and expenses:
Production and ad valorem taxes			15,638						16,039
Depletion			30,460						31,962
General and administrative expenses			2,139						1,880
Total costs and expenses			48,237						49,881
Income (loss) from operations			173,380						189,441
Other income (expense):
Interest expense, net			(10,731)						(9,782)
Gain (loss) on derivative instruments, net			882						(1,889)
Other income, net			162						32
Total other expense, net			(9,687)						(11,639)
Income (loss) before income taxes			163,693						177,802
Provision for (benefit from) income taxes			(46,409)						6,182
Net income (loss)			210,102						171,620
Net income (loss) attributable to non-controlling interest			130,762						137,598
Net income (loss) attributable to Viper Energy Partners LP			$	79,340					$	34,022

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The following table summarizes our production data, average sales prices and average costs for the periods indicated:

			Three Months Ended
			September 30, 2022						June 30, 2022
Production data:
Oil (MBbls)			1,828						1,798
Natural gas (MMcf)			4,086						3,898
Natural gas liquids (MBbls)			664						607
Combined volumes (MBOE)(1)			3,173						3,054
Average daily oil volumes (BO/d)			19,870						19,758
Average daily combined volumes (BOE/d)			34,489						33,560
Average sales prices:
Oil ($/Bbl)			$	91.87					$	106.34
Natural gas ($/Mcf)			$	7.01					$	6.10
Natural gas liquids ($/Bbl)			$	35.15					$	39.28
Combined ($/BOE)(2)			$	69.31					$	78.20
Oil, hedged ($/Bbl)(3)			$	91.26					$	105.59
Natural gas, hedged ($/Mcf)(3)			$	5.36					$	4.72
Natural gas liquids ($/Bbl)(3)			$	35.15					$	39.28
Combined price, hedged ($/BOE)(3)			$	66.82					$	75.99
Average costs ($/BOE):
Production and ad valorem taxes			$	4.93					$	5.25
General and administrative - cash component(4)			0.56						0.51
Total operating expense - cash			$	5.49					$	5.76
General and administrative - non-cash unit compensation expense			$	0.11					$	0.11
Interest expense, net			$	3.38					$	3.20
Depletion			$	9.60					$	10.47

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2)Realized price net of all deducts for gathering, transportation and processing.

(3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices.

(4)Excludes non-cash unit-based compensation expense for the respective periods presented.

Royalty Income

Our royalty income is a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes.

Royalty income decreased $18.9 million during the third quarter of 2022, compared to the second quarter of 2022. Changes in average pricing contributed approximately $25.5 million of the total decrease due primarily to lower average oil prices and to a lesser extent, natural gas liquids prices, offset slightly by higher average natural gas prices during the third quarter of 2022. The impact of lower pricing was partially offset by an increase of $6.6 million due to a 4% growth in production in the third quarter of 2022 compared to the second quarter of 2022. This production growth resulted from new wells additions between periods and having one additional day of production in the third quarter of 2022.

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Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the three months ended September 30, 2022 and June 30, 2022:

			Three Months Ended
			September 30, 2022																		June 30, 2022
			Amount (In thousands)						Per BOE						Percentage of Royalty Income						Amount (In thousands)						Per BOE						Percentage of Royalty Income
Production taxes			$	11,591					$	3.65					5.3		%				$	12,023					$	3.94					5.0		%
Ad valorem taxes			4,047						1.28						1.8						4,016						1.31						1.7
Total production and ad valorem taxes			$	15,638					$	4.93					7.1		%				$	16,039					$	5.25					6.7		%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of royalty income for the third quarter of 2022 were consistent with the second quarter of 2022. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes were also consistent between periods.

Depletion

The $1.5 million, or 5%, decrease in depletion expense for the third quarter of 2022 compared to the second quarter of 2022 was due primarily to a reduction in the average depletion rate to $9.60 for the three months ended September 30, 2022 compared to $10.47 for three months ended June 30, 2022. The rate decrease was primarily due to higher SEC oil and natural gas prices utilized in the reserve calculations in the third quarter of 2022, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells, as well as changes in cost to be excluded from depletion. The reduction in the average depletion rate was primarily offset by higher production in the third quarter of 2022.

Derivative Instruments

The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:

			Three Months Ended
			September 30, 2022						June 30, 2022
			(In thousands)
Gain (loss) on derivative instruments			$	882					$	(1,889)
Net cash receipts (payments) on derivatives(1)			$	(10,263)					$	(6,765)

(1)The three months ended September 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $2.4 million.

We recorded a gain on our derivative instruments for the third quarter of 2022, compared to a loss for the second quarter of 2022. This change is primarily due to market prices decreasing and in some cases being lower than the strike prices on our open oil and natural gas derivative contracts at September 30, 2022 compared to June 30, 2022. This gain was largely offset by net cash payments made to settle matured contracts and for the early termination of certain commodity contracts in the third quarter of 2022. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our condensed consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” See Note 10—Derivatives of the notes to the condensed consolidated financial statements included elsewhere in this report for additional discussion of our open contracts at September 30, 2022.

Provision for (Benefit from) Income Taxes

The $52.6 million decrease in income tax expense for the third quarter of 2022 compared to the second quarter of 2022 is primarily due to recognition of discrete income tax benefit as a result of the partial reduction of the valuation allowance against our deferred tax assets and to lower pre-tax net income driven primarily by a decrease in royalty income. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements included elsewhere in this report for further details.

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Comparison of the Nine Months Ended September 30, 2022 and 2021

Results of Operations

The following table summarizes our income and expenses for the periods indicated:

									Nine Months Ended September 30,
															2022						2021
															(In thousands)
Operating income:
Oil income															$	514,180					$	272,450
Natural gas income															67,621						30,651
Natural gas liquids income															70,027						34,518
Royalty income															651,828						337,619
Lease bonus income															10,508						1,032
Other operating income															506						479
Total operating income															662,842						339,130
Costs and expenses:
Production and ad valorem taxes															45,547						23,426
Depletion															89,833						74,230
General and administrative expenses															5,972						6,118
Total costs and expenses															141,352						103,774
Income (loss) from operations															521,490						235,356
Other income (expense):
Interest expense, net															(30,158)						(24,161)
Gain (loss) on derivative instruments, net															(19,366)						(70,649)
Other income, net															200						77
Total other expense, net															(49,324)						(94,733)
Income (loss) before income taxes															472,166						140,623
Provision for (benefit from) income taxes															(37,597)						941
Net income (loss)															509,763						139,682
Net income (loss) attributable to non-controlling interest															379,796						121,208
Net income (loss) attributable to Viper Energy Partners LP															$	129,967					$	18,474

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The following table summarizes our production data, average sales prices and average costs for the periods indicated:

									Nine Months Ended September 30,
															2022						2021
Production data:
Oil (MBbls)															5,259						4,378
Natural gas (MMcf)															11,713						9,828
Natural gas liquids (MBbls)															1,857						1,359
Combined volumes (MBOE)(1)															9,068						7,375
Average daily oil volumes (BO/d)															19,264						16,037
Average daily combined volumes (BOE/d)															33,216						27,015
Average sales prices:
Oil ($/Bbl)															$	97.77					$	62.23
Natural gas ($/Mcf)															$	5.77					$	3.12
Natural gas liquids ($/Bbl)															$	37.71					$	25.40
Combined ($/BOE)(2)															$	71.88					$	45.78
Oil, hedged ($/Bbl)(3)															$	96.40					$	48.26
Natural gas, hedged ($/Mcf)(3)															$	4.62					$	3.12
Natural gas liquids ($/Bbl)(3)															$	37.71					$	25.40
Combined price, hedged ($/BOE)(3)															$	69.60					$	37.48
Average costs ($/BOE):
Production and ad valorem taxes															$	5.02					$	3.18
General and administrative - cash component(4)															0.55						0.70
Total operating expense - cash															$	5.57					$	3.88
General and administrative - non-cash unit compensation expense															$	0.11					$	0.13
Interest expense, net															$	3.33					$	3.28
Depletion															$	9.91					$	10.07

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2)Realized price net of all deducts for gathering, transportation and processing.

(3)Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices.

(4)Excludes non-cash unit-based compensation expense for the respective periods presented.

Royalty Income

Our royalty income is a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes.

Royalty income increased $314.2 million during the nine months ended September 30, 2022 compared to the same period in 2021. As discussed in “—Recent Developments,” strong oil prices in 2022 and to a lesser extent, the continuing recovery in natural gas and natural gas liquids prices, contributed to approximately $240.9 million of the total increase.

The remaining $73.3 million of the total increase in royalty income is attributable to the 23% increase in production volumes during the nine months ended September 30, 2022 compared to the same period in 2021. This production growth stems from new well additions between periods primarily due to the Swallowtail Acquisition.

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Lease Bonus Income

Lease bonus income increased during the nine months ended September 30, 2022 compared to the same period in 2021 due primarily to leasing certain assets we acquired in the Swallowtail Acquisition to Diamondback in the first quarter of 2022.

Production and Ad Valorem Taxes

The following table presents production and ad valorem taxes for the nine months ended September 30, 2022 and 2021:

			Nine Months Ended September 30,
			2022																		2021
			Amount (In thousands)						Per BOE						Percentage of Royalty Income						Amount (In thousands)						Per BOE						Percentage of Royalty Income
Production taxes			$	33,484					$	3.69					5.1		%				$	17,264					$	2.34					5.1		%
Ad valorem taxes			12,063						1.33						1.9						6,162						0.84						1.8
Total production and ad valorem taxes			$	45,547					$	5.02					7.0		%				$	23,426					$	3.18					6.9		%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of royalty income for the nine months ended September 30, 2022 remained consistent with the same period in 2021. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. The increase in ad valorem taxes is primarily due to accruing taxes for the properties acquired in the Swallowtail Acquisition, as well as higher valuations assigned to our other oil and natural gas interests period over period driven by higher average commodity prices. Ad valorem taxes remained consistent as a percentage of royalty income for the nine months ended September 30, 2022 compared to the same period in 2021.

Depletion

The $15.6 million, or 21%, increase in depletion expense for the nine months ended September 30, 2022 compared to the same period in 2021 was due primarily to production growth between the periods. The average depletion rate decreased to $9.91 for the nine months ended September 30, 2022 compared to the rate of $10.07 for the same period in 2021. The rate decrease largely resulted from higher SEC oil and natural gas prices utilized in the reserve calculations in 2022, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.

Derivative Instruments

The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:

			Nine Months Ended September 30,
			2022						2021
			(In thousands)
Gain (loss) on derivative instruments			$	(19,366)					$	(70,649)
Net cash receipts (payments) on derivatives(1)			$	(27,292)					$	(61,188)

(1)The nine months ended September 30, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $6.6 million.

We recorded losses on our derivative instruments for the nine months ended September 30, 2022 and 2021 primarily due to market prices being higher than the strike prices on our derivative contracts. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our condensed consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.”

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Interest Expense, Net

The $6.0 million increase in net interest expense for the nine months ended September 30, 2022 compared to the same period in 2021 was due primarily to an increase in average outstanding borrowings and interest rates on the Operating Company’s revolving credit facility.

Provision for (Benefit from) Income Taxes

Income tax benefit for the nine months ended September 30, 2022 of $37.6 million resulted primarily from recognition of discrete income tax benefit as a result of the partial reduction in the valuation allowance against our deferred tax assets. This was partially offset by an increase in current tax expense due to the increase in pre-tax income, which was driven largely by increases in royalty income and lease bonus income as well as changes in the gain or loss recognized on our derivative contracts as discussed above. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements included elsewhere in this report for further details.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations and liquidity requirements. Our future ability to grow proved reserves will be highly dependent on the capital resources available to us. Our primary sources of liquidity have been cash flows from operations, proceeds from sales of non-core assets and investments, equity and debt offerings and borrowings under the Operating Company’s credit agreement. Our primary uses of cash have been distributions to our unitholders, repayments of debt, capital expenditures for the acquisition of our mineral interests and royalty interests in oil and natural gas properties and repurchases of our common units. At September 30, 2022, we had approximately $266.6 million of liquidity consisting of $11.6 million in cash and cash equivalents and $255.0 million available under the Operating Company’s credit agreement.

Our working capital requirements are supported by our cash and cash equivalents and the Operating Company’s credit agreement. We may draw on the Operating Company’s credit agreement to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our acquisitions of mineral and royalty interests, distributions, debt service obligations and repayment of debt maturities, common unit and senior note repurchases and any amounts that may ultimately be paid in connection with contingencies.

In order to mitigate volatility in oil and natural gas prices, we have entered into commodity derivative contracts as discussed further in Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.

Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the war in Ukraine, the depressed commodity markets and, or adverse macroeconomic conditions, including persistent inflation, rising interests rates, global supply chain disruptions and increasing concerns over a potential economic downturn or recession, may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although we expect that our sources of funding will be adequate to fund our short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.

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Cash Flows

The following table presents our cash flows for the periods indicated:

			Nine Months Ended September 30,
			2022						2021
			(In thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities			$	513,241					$	199,672
Net cash provided by (used in) investing activities			19,611						(6,728)
Net cash provided by (used in) financing activities			(560,684)						(140,525)
Net increase (decrease) in cash and cash equivalents			$	(27,832)					$	52,419

Operating Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volumes of oil and natural gas sold by our producers. The increase in net cash provided by operating activities during the nine months ended September 30, 2022 compared to the same period in 2021 was primarily driven by (i) higher royalty income, (ii) an increase in lease bonus income and (iii) a decrease in cash paid for derivative settlements. These increases in cash flow were partially offset by (i) changes in our working capital accounts, most notably through an increase in our accounts receivable in 2022 compared to 2021 due primarily to higher market prices for our oil sales and the timing of our receipt of royalty income payments from our operators (ii) an increase in production and ad valorem expenses due to the corresponding increase in royalty income and (iii) an increase in cash paid for taxes, as our tax provision reflects an increase in current cash income taxes. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.

Investing Activities

Net cash provided by investing activities during the nine months ended September 30, 2022 primarily related to proceeds from the divestitures of oil and natural gas interests, partially offset by expenditures for acquisitions of oil and natural gas interests.

Net cash used in investing activities during the nine months ended September 30, 2021 primarily related to acquisitions of oil and natural gas interests.

Financing Activities

Consistent with our strategy to return cash flow to unitholders, net cash used in financing activities during the nine months ended September 30, 2022 was primarily related to distributions of $333.7 million to our unitholders and $118.9 million of common unit repurchases which included approximately $37.3 million for the repurchase of 1.5 million common units from a significant unitholder in a privately negotiated transaction. Additionally, we paid approximately $49.0 million for the repurchase of principal outstanding on the Notes as discussed in “—2022 Debt Transactions” below and made net repayments of $59.0 million of borrowings under the Operating Company’s revolving credit facility using cash on hand.

Net cash used in financing activities during the nine months ended September 30, 2021, was primarily related to net borrowings of $8.0 million under the Operating Company’s revolving credit facility, distributions of $112.0 million to our unitholders and $33.6 million of repurchases of our common units during the third quarter of 2021.

Capital Resources

The Operating Company’s Revolving Credit Facility

At September 30, 2022, the Operating Company had elected a commitment amount of $500.0 million on its credit agreement with $245.0 million of outstanding borrowings.

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2022 Debt Transactions

During the nine months ended September 30, 2022, the Operating Company used a combination of cash on hand and borrowings under the Operating Company’s credit agreement to repurchase a portion of the 5.375% 2027 Senior Notes in the aggregate principal amount of $49.6 million for total cash consideration of $49.0 million.

The Operating Company is currently in compliance, and expects to be in compliance, with all financial maintenance covenants under its credit agreement. See Note 6—Debt of the notes to the condensed consolidated financial statements included elsewhere in this report for additional discussion of our outstanding debt at September 30, 2022.

Capital Requirements

Repurchases of Securities

On July 26, 2022, the board of directors of our General Partner increased the authorization of our common unit repurchase program from $250.0 million to $750.0 million. As of September 30, 2022, $561.0 million remains available for use to repurchase units under the repurchase program.

We may also from time to time opportunistically repurchase some of the outstanding Notes in open market purchases or in privately negotiated transactions.

Cash Distributions

The distribution for the third quarter of 2022 is $0.49 per common unit payable on November 25, 2022 to common unitholders of record at the close of business on November 17, 2022. The dividend consists of a base quarterly dividend of $0.25 per common unit and a variable quarterly dividend of $0.24 per common unit. Future base and variable dividends are at the discretion of the board of directors of our General Partner.

See “—Recent Developments—Cash Distributions on Common Units” and Note 7—Unitholders' Equity and Distributions of the notes to the condensed consolidated financial statements included elsewhere in this report for further discussion of the repurchase program and distributions.

Critical Accounting Estimates

There have been no changes to our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2021.

Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report for recent accounting pronouncements not yet adopted, if any.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized prices are driven primarily by the prevailing worldwide price for crude oil and prices for natural gas in the United States. Both crude oil and natural gas realized prices are also impacted by the quality of the product, supply and demand balances in local physical markets and the availability of transportation to demand centers. Pricing for oil and natural gas production has been historically volatile and unpredictable and the prices that our operators receive for production depend on many factors outside of our or their control, such as the war in Ukraine, rising interest rates, global supply chain disruptions, a potential economic downturn or recession, the COVID-19 pandemic and actions taken by OPEC members and other exporting

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nations. We cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.

We historically have used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our royalty income as discussed in Note 10 — Derivatives of the notes to the condensed consolidated financial statements included elsewhere in this report.

At September 30, 2022, we had a net asset derivative position related to our commodity price derivatives of $4.5 million. Utilizing actual derivative contractual volumes under our contracts as of September 30, 2022, a 10% increase in forward curves associated with the underlying commodity would have increased the net asset position by $0.6 million to $5.1 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net asset derivative position by $0.3 million to $4.2 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

Credit Risk

We are subject to risk resulting from the concentration of royalty income in producing oil and natural gas interests and receivables with a limited number of significant purchasers and producers. We do not require collateral and the failure or inability of our significant purchasers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. Volatility in commodity pricing environment and macroeconomic conditions may enhance our purchaser credit risk.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under the Operating Company’s credit agreement. The terms of the credit agreement provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which is the least of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. As of September 30, 2022, we had $245.0 million in outstanding borrowings. During the three and nine months ended September 30, 2022, the weighted average interest rate on the Operating Company’s revolving credit facility was 4.75% and 3.53%, respectively.

ITEM 4.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures. Under the direction of the Chief Executive Officer and Chief Financial Officer of our General Partner, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of September 30, 2022, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner have concluded that as of September 30, 2022, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2022 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1.     LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Note 12—Commitments and Contingencies.

ITEM 1A.     RISK FACTORS

Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.

As of the date of this filing, we continue to be subject to the risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 24, 2022, Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022, filed with the SEC on May 5, 2022, Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2022, filed with the SEC on August 3, 2022, and in subsequent filings we make with the SEC. There have been no material changes in our risk factors from those described in such reports.

ITEM 2.     UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common unit repurchase activity for the three months ended September 30, 2022 was as follows:

Period						Total Number of Units Purchased(1)						Average Price Paid Per Unit(2)						Total Number of Units Purchased as Part of Publicly Announced Plan						Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(3)
						(In thousands, except unit amounts)
July 1, 2022 - July 31, 2022						760,000						$	26.51					760,000						$	591,618
August 1, 2022 - August 31, 2022						529,972						$	29.37					529,972						$	576,050
September 1, 2022 - September 30, 2022						527,745						$	28.44					527,745						$	561,043
Total						1,817,717						$	27.91					1,817,717

(1)Includes common units repurchased from employees in order to satisfy tax withholding requirements, if any. Such units are cancelled and retired immediately upon repurchase.

(2)The average price paid per common unit includes any commissions paid to repurchase a common unit.

(3)On July 26, 2022, the board of directors of our General Partner increased the authorization of our then-in-effect common unit repurchase program from $250.0 million to $750.0 million. This repurchase program remains subject to market conditions, applicable legal requirements, contractual obligations and other factors and may be suspended from time to time, modified, extended or discontinued by the board of directors of our General Partner at any time.

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ITEM 6.     EXHIBITS

Exhibit Number						Description
2.1						Purchase and Sale Agreement dated August 6, 2021 by and among Swallowtail Royalties LLC, Swallowtail Royalties II LLC (collectively, as seller), Viper Energy Partners LLC (as buyer) and Viper Energy Partners LP (as parent, and collectively with Viper Energy Partners LLC, as buyer parties) (incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on August 12, 2021).
3.1						Certificate of Limited Partnership of Viper Energy Partners LP (incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File 333-195769) filed on May 7, 2014).
3.2						Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 9, 2018 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.3						First Amendment to Second Amended and Restated Agreement of Limited Partnership of Viper Energy Partners LP, dated as of May 10, 2018. (incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.4						Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of May 9, 2018. (incorporated by reference to Exhibit 3.3 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
3.5						First Amendment to Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of March 30, 2020 (incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on March 31, 2020).
3.6						Second Amendment to the Second Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, dated as of December 27, 2021 (incorporated by reference to 3.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on December 28, 2021).
4.1						Amended and Restated Registration Rights Agreement, dated as of May 9, 2018, by and between Viper Energy Partners LP and Diamondback Energy, Inc. (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on May 15, 2018).
4.2						Registration Rights Agreement, dated as of October 1, 2021, by and among Viper Energy Partners LP, Swallowtail Royalties LLC and Swallowtail Royalties II LLC (incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File 001-36505) filed on October 7, 2021).
31.1*						Certification of Chief Executive Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*						Certification of Chief Financial Officer pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**						Certification of Chief Executive Officer and Chief Financial Officer pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101						The following financial information from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2022, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement of Changes in Unitholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Condensed Notes to Consolidated Financial Statements.
104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*			Filed herewith.
**			The certifications attached as Exhibit 32.1 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

						VIPER ENERGY PARTNERS LP
						By:			VIPER ENERGY PARTNERS GP LLC
									its General Partner
Date:			November 8, 2022			By:			/s/ Travis D. Stice
									Travis D. Stice
									Chief Executive Officer
Date:			November 8, 2022			By:			/s/ Teresa L. Dick
									Teresa L. Dick
									Chief Financial Officer

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